Company Update (NYSE:PVA): Penn Virginia Corporation Announces Third Quarter 2015 Results


Penn Virginia Corporation (NYSE:PVA) reported financial results for the three months endedSeptember 30, 2015 and provided updates of its operations and guidance.

Key Highlights

Third quarter 2015 results compared, as applicable, to second quarter 2015 results were as follows:

  • Total production was 20,976 barrels of oil equivalent (BOE) per day (BOEPD), compared to 23,519 BOEPD.
    • Total production was above the midpoint of production guidance of 18,500 to 22,800 BOEPD.
  • The average initial potential (IP) and 30-day rates for 11 Eagle Ford wells turned in line were 1,501 and 790 BOEPD, up 88% and 59% compared to 798 and 497 BOEPD for 16 wells turned in line in the second quarter.
  • Gross drilling and completion costs for the 11 wells, including facilities, averaged $5.7 million per well, approximately 30% lower than the average cost of the 16 second quarter wells.
    • The decrease in average well cost was driven by a transition to drilling exclusively two-string wells, whereas only three of the second quarter wells were two-string wells. In addition, seven of the third quarter wells were slickwater stimulated and all of the third quarter wells were fractured with approximately 46% more proppant per stage, on average, than second quarter wells.
  • Product revenues, including derivatives, were $93.0 million, compared to $118.0 million.
    • Realized oil, gas and natural gas liquids (NGLs) prices were $69.19 per barrel, $2.68 per thousand cubic feet (Mcf) and $9.81 per barrel, compared to $82.44 per barrel, $2.54 per Mcf and $13.53 per barrel, including hedges.
    • Product revenues per BOE were $48.17, compared to $55.12, including hedges.
  • Production costs, including lease operating expense, gathering, processing and transportation expenses and production and ad valorem taxes, decreased 8% to $20.4 million from $22.3 million.
  • Recurring general and administrative (G&A) costs decreased 12% to $8.2 million from $9.4 million.
  • Adjusted EBITDAX, a non-GAAP (generally accepted accounting principles) measure, was $65.0 million, compared to $85.5 million.

Other updates included:

  • The borrowing base under the revolving credit facility (Revolver) was recently redetermined to $275 million.
    • The lower borrowing base was in line with our expectations.
    • At September 30, 2015, our pro forma financial liquidity was $136 million and our leverage ratio was 3.9 times.
    • Year-end 2015 liquidity is expected to be $103 to $118 million.
  • Preliminarily, we estimate 2016 capital expenditures to be between $140 and $160 million, down from earlier preliminary guidance of $200 to$250 million.
    • Fourth quarter 2016 oil production is now expected to be approximately 5% less than fourth quarter 2015.

Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release.

Management Comment

Edward B. Cloues, II, Chairman and interim Chief Executive Officer stated, “Our third quarter results were largely as expected, despite lower than anticipated oil prices, as our operating costs continued to decrease. Our third quarter production came in slightly above the midpoint of third quarter guidance, due primarily to the higher productivity of our most recent wells. In particular, we were encouraged with the early results of our most recent seven two-string, slickwater fracked wells in the Lower Eagle Ford, both in terms of their average cost and initial productivity. The last five of these wells, also utilizing zipper fracs, were on average the best wells we have drilled out of nearly 330 producing wells we and our partners have drilled over the past five years. The higher initial production of our wells turned in line in the third quarter, and the lower costs of those wells, which were 30% lower than the average cost of wells we turned in line in the second quarter, should generate higher than historical internal rates of return even in the current price environment.

“We will continue to focus our drilling efforts on two-string, Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County, where we believe our rates of return are optimized. The redirection of our drilling program to this lower-cost area, where we have experienced higher productivity with the slickwater fracs, has led us to reduce preliminary capital expenditures guidance for 2016 for a 1-rig drilling program, as detailed later in this release.”

Mr. Cloues concluded, “With respect to financial liquidity, our borrowing base redetermination, while lower, was in line with our expectations given the current commodity price environment. To further supplement liquidity, during the third quarter and in early October we sold our East Texas and certain non-core Eagle Ford assets for gross proceeds of $88 million. However, we anticipate that we will exceed the total debt leverage covenant in the Revolver at the end of the first quarter of 2016, which would require us to seek a waiver from our bank lenders, which may or may not be forthcoming. Consequently, we are actively reviewing various financing and debt restructuring alternatives in an attempt to shore up our overall liquidity and relieve our dependence upon the Revolver as our sole source of external funding.”

Third Quarter 2015 Results

Overview of Results

Operating income was $3.6 million in the third quarter of 2015, compared to an operating loss of $41.0 million in the second quarter of 2015. This $44.6 million improvement was due primarily to $50.8 million of gains related to asset sales and a $16.2 million decrease in operating expenses, partially offset by a $22.4 million decrease in product revenues.

Net income attributable to common shareholders for the third quarter was $20.0 million, or $0.25 per diluted share, compared to net loss of$86.2 million, or $1.19 per diluted share, in the prior quarter. The primary reasons for the $106.2 million improvement were the $44.6 million increase in operating income and a $60.2 million increase in derivatives income, which includes mark-to-market adjustments. Adjusted net loss attributable to common shareholders, a non-GAAP measure which includes our preferred stock dividend but excludes the effects of non-cash derivatives expense and other items that affect comparability to other periods, was $43.3 million, or $0.60 per diluted share, for the third quarter compared to a loss of$31.6 million, or $0.44 per diluted share, in the prior quarter. The primary reasons for the $11.6 million increase in the loss were the $22.4 milliondecrease in product revenues and a $2.6 million decrease in cash settlements of derivatives, partially offset by the $16.2 million decrease in operating expenses.

Production

As shown in the table below, total production in the third quarter of 2015 was 20,976 BOEPD, compared to 23,519 BOEPD in the second quarter of 2015, with a 1,731 BOEPD decrease in the Eagle Ford and an 812 BOEPD decrease in other areas, primarily related to the sale of East Texas assets inAugust 2015. Pro forma for the sale of East Texas, production declined by 1,764 BOEPD to 19,857 BOEPD in the third quarter of 2015 from 21,621 BOEPD in the prior quarter.

  Total and Daily Equivalent Production for the Three Months Ended
 
Region / Play Type
Sept. 30,
2015
June 30,
2015
Sept. 30,
2014
Sept. 30,
2015
June 30,
2015
Sept. 30,
2014
  (in MBOE) (in BOEPD)
             
Eagle Ford Shale 1,705 1,844 1,557 18,528 20,259 16,929
Mid-Continent 117 119 258 1,271 1,302 2,802
Other 108 177 274 1,177 1,958 2,975
Totals 1,930 2,140 2,089 20,976 23,519 22,706
Pro Forma Totals(1) 1,827 1,967 1,712 19,857 21,621 18,617
 
Note – Numbers may not add due to rounding. MBOE equals one thousand barrels of oil equivalent.
(1) Pro forma to exclude volumes from divested Mississippi and East Texas properties, as well as the third quarter 2014 Mid-Continent adjustment.

Product Revenues

Total product revenues decreased by $22.4 million, or 27%, to $60.7 million, or $31.45 per BOE, in the third quarter of 2015, from $83.1 million, or$38.84 per BOE, in the second quarter of 2015, due primarily to a 19% decrease in the realized oil equivalent price and an 11% decrease in production. For the third quarter, the realized oil price decreased by 23%, the realized natural gas price increased by 5% and the realized NGL price decreased by 27% compared to the second quarter of 2015. Including derivatives, total product revenues were $93.0 million, or $48.17 per BOE, in the third quarter of 2015, compared to $118.0 million, or $55.12 per BOE, in the second quarter of 2015.

Operating Expenses

As discussed below, third quarter 2015 total direct operating expenses, excluding share-based compensation and non-recurring expenses, decreased by $3.0 million to $28.7 million, or $14.87 per BOE produced, from $31.7 million, or $14.80 per BOE produced, in the second quarter of 2015.

  • Lease operating expense increased by $0.4 million to $11.3 million, or $5.86 per BOE, from $10.9 million, or $5.10 per BOE, due to increased compression and saltwater disposal expenses, partially offset by decreased workover and chemicals and fluids expenses.
  • Gathering, processing and transportation expense decreased by $0.7 million to $5.7 million, or $2.93 per BOE, from $6.4 million, or $2.98 per BOE, due to decreased production volumes.
  • Production and ad valorem taxes decreased by $1.5 million to $3.5 million, or 5.7% of product revenues, from $5.0 million, or 6.0% of product revenues, due to lower commodity prices.
  • Recurring G&A expense decreased by $1.2 million to $8.2 million, or $4.27 per BOE, from $9.4 million, or $4.40 per BOE. The decrease in recurring G&A expense was due primarily to lower consulting and professional fees and salary and wages expense.

Depletion, depreciation and amortization expense in the third quarter of 2015 decreased by $8.5 million to $76.9 million, or $39.82 per BOE, from$85.4 million, or $39.91 per BOE, in the second quarter.

Capital Expenditures

During the third quarter of 2015, capital expenditures were $40 million, a decrease of $54 million, or 58%, compared to $94 million in the second quarter of 2015, consisting of:

  • A decrease of approximately $48 million for drilling and completion activities, to approximately $40 million.
  • A net decrease of approximately $6 million to approximately zero for pipeline, gathering, facilities, seismic, leasehold acquisition and other capital expenditures.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of September 30, 2015, we had total debt of $1,215 million, consisting of $300 million principal amount of 7.25% senior unsecured notes due 2019,$775 million principal amount of 8.50% senior unsecured notes due 2020 and $140 million drawn under the Revolver, down $72 million from June 30, 2015. In November 2015, the borrowing base under the Revolver was reduced from $395 million to $275 million, which was in line with our expectations. Together with cash and equivalents of $3 million and net of letters of credit of $2 million, our financial liquidity was $256 million atSeptember 30, 2015. Pro forma liquidity, after giving effect to the new borrowing base of $275 million, was $136 million.

Our total debt leverage ratio under the Revolver at September 30, 2015 was 3.9 times trailing twelve months’ Adjusted EBITDAX of $313 million. The maximum leverage ratio allowable during the third quarter of 2015 under the Revolver was 4.75 times. An additional covenant for credit exposure, defined as all outstanding borrowings under the Revolver plus any outstanding letters of credit, has a maximum allowable ratio of 2.75 times throughMarch 31, 2017. At September 30, 2015, this ratio was 0.5 times.

During the third quarter, interest expense was $23.0 million, of which $21.8 million was cash interest expense, unchanged from the second quarter.

During the third quarter, derivatives income was $44.7 million, compared to derivatives expense of $15.5 million in the second quarter. Third quarter cash settlements of derivatives resulted in net cash receipts of $32.3 million, compared to $34.8 million of net cash receipts in the second quarter.

Derivatives Update

To support our operating cash flows, we hedge a portion of our oil and natural gas production at predetermined prices or price ranges. Currently, we have hedged 11,000 barrels of daily crude oil production during the fourth quarter of 2015, or about 90% to 100% of our expected oil production, at a weighted average floor/swap price of $89.86 per barrel. We have sold put options for 5,000 barrels of daily crude oil production during the fourth quarter of 2015, with all put options sold at a strike price of $70.00 per barrel. For 2016, we have hedged 6,000 barrels of daily crude oil production at a weighted average floor/swap price of $80.41 per barrel. We currently do not have any natural gas derivatives.

Please see the Derivatives Table included in this release for our current derivative positions.

Full-Year 2015 Guidance Update and Preliminary 2016 Guidance

Full-year 2015 guidance highlights are as follows:

  • Production of approximately 21,300 to 21,800 BOEPD, compared to previous guidance of approximately 20,700 to 22,600 BOEPD.
    • 2015 crude oil production of approximately 13,200 to 13,500 barrels of oil per day (BOPD), compared to previous guidance of 13,050 to 14,350 BOPD.
    • Production in the fourth quarter of 2015 is expected to range between approximately 16,200 and 18,100 BOEPD, compared to previous guidance of between 16,300 and 19,600 BOEPD.
  • Product revenues, excluding the impact of any derivatives, are expected to be $264 to $269 million, compared to previous guidance of $284 to$307 million.
    • Our crude oil revenue estimate assumes realized pricing of West Texas Intermediate (WTI) crude oil benchmark pricing of approximately $45 per barrel, compared to previous guidance of $55 per barrel. Benchmark (Henry Hub) natural gas pricing is assumed to be $2.56 per Mcf, compared to previous guidance of $2.88 per Mcf, while NGL pricing is assumed to be 19% of the WTI price.
    • Cash receipts from the settlement of derivatives are expected to be $134 million, based on the foregoing assumptions, compared to previous guidance of $127 million.
  • Adjusted EBITDAX, a non-GAAP measure, is expected to be $280 to $284 million, compared to previous guidance of $285 to $310 million.
  • Capital expenditures are expected to be $316 to $324 million, compared to previous guidance of $325 to $345 million.
    • Drilling and completion capital expenditures are expected to be $296 to $302 million, compared to previous guidance of $305 to $320 million.
    • Pipeline, gathering, facilities, seismic and other capital expenditures are expected to be $6 to $7 million, compared to previous guidance of $5 to $8 million.
    • Lease acquisition capital expenditures are expected to be $14 to $15 million, essentially unchanged compared to previous guidance.

Please see the Guidance Table included in this release for guidance estimates for fourth quarter and full-year 2015.

Preliminarily, and based on crude oil prices, specifically $48 to $52 per barrel WTI, we expect to spend $140 to $160 million in capital expenditures during 2016, with fourth quarter 2016 oil production approximately 5% lower than the midpoint of fourth quarter 2015 oil production guidance (overall production approximately 10% lower). This compares to previous preliminary guidance, which assumed a $55 to $60 per barrel WTI crude oil pricing, of$200 to $250 million in capital expenditures during 2016. The 2016 preliminary capital budget will be funded by anticipated year-end 2015 liquidity and 2016 cash flows from operating activities.

2015 estimates and 2016 preliminary estimates are meant to provide guidance only and are subject to revision as the operating environment changes.

Eagle Ford Shale Operational Update

Third Quarter 2015 Update

Third quarter production from our Eagle Ford operations was 18,528 BOEPD, a 9% decrease from the 20,259 BOEPD produced in the second quarter of 2015. Approximately 69% of our third quarter Eagle Ford production was from crude oil, 18% was from NGLs and 13% was from natural gas. The decrease was attributable primarily to our reduction in drilling activity as the year progressed, in light of lower oil and gas prices.

Well Cost Reductions and Improved Well Results

The average gross well cost for 11 (two-string) wells turned in line during the third quarter of 2015 was approximately $5.7 million, down 30% from an average of $8.2 million for 16 (two-string and three-string wells) wells turned in line in the second quarter of 2015. The decrease in average well cost was driven by a transition to drilling exclusively two-string wells, whereas only three of the second quarter wells were two-string wells. In addition, seven of the third quarter wells were slickwater stimulated and all of the third quarter wells were fractured with approximately 46% more proppant per stage, on average, than second quarter wells.

Recent Eagle Ford Well Results

Below are the results and statistics for Eagle Ford wells over the past five quarters: (2)

    Averages
        Peak Gross Daily
Production Rates(3)
30-Day Average Gross Daily
Production Rates(3)
  Gross /
Net Wells
Lateral
Length
Frac
Stages
 
Proppant
Oil
Rate
Equivalent
Rate
Oil
Percentage
Oil
Rate
Equivalent
Rate
Oil
Percentage
    Feet   lbs. BOPD BOEPD   BOPD BOEPD  
Time Period                    
2014 – 3rd quarter 22 / 12.2 5,813 27.4 10,129,710 1,050 1,244 85% 659 777 85%
2014 – 4th quarter 23 / 17.1 5,486 25.7 9,849,071 880 1,256 70% 634 900 72%
2015 – 1st quarter 25 / 13.7 6,345 27.2 8,089,820 1,048 1,254 84% 681 805 85%
2015 – 2nd quarter 16 / 11.4 6,008 24.4 7,014,972 604 798 76% 388 497 77%
2015 – 3rd quarter 11 / 8.5 5,040 21.2 9,082,417 1,381 1,501 93% 726 790 92%
Totals and averages 97 / 62.9 5,817 25.7 8,904,885 973 1,205 81% 622 769 82%
                     
Operating Area                    
Peach Creek 14 / 8.6 5,128 23.6 9,677,214 1,364 1,488 92% 756 819 93%
Rock Creek / Bozka 8 / 3.7 5,461 25.9 9,517,026 1,313 1,486 88% 910 1,032 88%
Upper Eagle Ford 30 / 24.3 6,002 26.0 8,724,670 614 960 68% 465 710 70%
Lavaca “Beer Area” 20 / 9.4 6,032 27.2 9,505,123 1,128 1,387 81% 715 862 82%
Shiner 9 / 6.8 5,932 24.8 7,179,445 899 1,205 73% 546 715 75%
Shallow Gonzales 16 / 10.0 5,917 25.6 8,481,194 983 1,049 94% 579 615 94%
Totals and averages 97 / 62.9 5,817 25.7 8,904,885 973 1,205 81% 622 769 82%
 
(2) Excludes two Upper Eagle Ford wells and one Lower Eagle Ford well which had mechanical issues.
(3) Wellhead rates only; the natural gas associated with these wells is yielding between 135 and 155 barrels of NGLs per million cubic feet.

Since the end of the second quarter of 2015, we have turned in line 11 (8.5 net) operated wells. As a group, these 11 wells had an average IP rate of 1,501 BOEPD over an average of 21.2 frac stages, with 93% of production from crude oil, compared to 798 BOEPD over an average of 24.4 stages for 16 second quarter wells. All of the third quarter wells were drilled in the Lower Eagle Ford and had a 30-day average rate of 790 BOEPD, with 92% of production from crude oil, compared to an average of 497 BOEPD for the second quarter wells. The average amount of proppant per stage for these 11 wells was approximately 422,000 pounds and the average amount of proppant per lateral foot was approximately 1,800 pounds, compared to approximately 290,000 pounds per stage and 1,170 pounds per lateral foot in the second quarter of 2015. We believe the strong improvement in early-time production rates is attributable to the use of slickwater stimulations, continued use of “zipper” fracs for alternating laterals on multi-well pads and increased frac intensity as measured by the increased proppant pumped per stage.

Drilling Program Outlook

For the remainder of 2015 and for 2016, due primarily to anticipated low oil prices, we will continue to focus our efforts on drilling, using one rig, less costly two-string Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County where our economics are optimized. (Original Source)

Shares of Penn Virginia Resource closed today at $0.80, up $0.06 or 8.06%. PVA has a 1-year high of $9.63 and a 1-year low of $0.34. The stock’s 50-day moving average is $0.76 and its 200-day moving average is $2.64.

On the ratings front, Penn Virginia Resource has been the subject of a number of recent research reports. In a report issued on August 10, Barclays analyst Jeffrey Robertson reiterated a Hold rating on PVA, with a price target of $1, which implies an upside of 33.3% from current levels. Separately, on August 3, Canaccord Genuity’s Stephen Berman reiterated a Buy rating on the stock and has a price target of $3.75.

According to TipRanks.com, which ranks over 7,500 financial analysts and bloggers to gauge the performance of their past recommendations, Jeffrey Robertson and Stephen Berman have a total average return of 3.9% and -27.5% respectively. Robertson has a success rate of 48.1% and is ranked #966 out of 3829 analysts, while Berman has a success rate of 26.4% and is ranked #3827.

Penn Virginia Corp is an independent oil and gas company. The Company is engaged in the exploration, development and production of crude oil, natural gas liquids and natural gas in onshore regions of the United States.